This paper provides a case study for the application of gas assisted gravity drainage (GAGD) EOR in the Donghe I carboniferous reservoir, which is ultra-deep (>16,000 ft), thick (150-400 ft) and has high temperature, pressure, and salinity values of 410 K, 6500–8500 psi and > 200,000 ppm, respectively. The study aims to mitigate the problems faced by this reservoir such as high degree of reserve recovery (40%), high water cut (> 82%), low reservoir pressure (pressure maintenance level < 0.65), and low production rate. The techniques described in this paper are based on natural gas miscible flooding in which the GAGD technique occupies the dominant position, with the plane displacement technique being assisted. A reservoir description focusing on fine characterization of the interlayer has been applied combined with a compositional ten-million-grid-scale reservoir simulation model to make the filtration mechanism be straightforwardness. Laboratory experiments were conducted to reveal the phase behavior of reservoir fluids after gas flooding. Several key methods have been established including gas breakthrough indication by composition, well pattern reconstruction, injection/production matching, typical treatment for typical wells, and injection/production ratio control. The aforementioned techniques and methods mentioned have been carried out in Donghe I carboniferous reservoir as part of a geology-reservoir-engineering-economics-HSE integral project. The daily gas injection rate at the pilot site is around 1.4 MMCF/D using 4 horizontal wells as gas injectors and the injection/production ratio is over 1.5, which is considered a satisfactory result. As of 2018, there are 13 response producers of 25 wells in this reservoir, of which 6 wells showed doubling or tripling of daily production and 5 wells transferred from artificial lifting to natural flow, with production of two of the producers exceeding 650 BPOD. The cumulated oil production and gas injection have respectively reached 1.6 MMbbl and 10.2 BCF. The injected gas serves as an effective supplement to reservoir energy, causing the pressure maintenance level to climb up to 0.8. The gas injection has also had a positive effect on the composite production decrement and composite water cut of this reservoir. The composite production decrement has declined from 15.5%/A before gas flooding to about zero after gas flooding till date, and the production still has a trend to change from constant rate to rising rate. Simultaneously, the water cut which was previously increasing has now started dropping down. The promoted GAGD EOR technique showcased in this paper effectively combines a series of technical and theoretical methods including natural gas miscible flooding, GAGD with plane gas displacement, gas breakthrough indication by composition, injection/production matching, typical treatment for typical well, injection/production ratio controlling, ten-million-grid-scale compositional-model simulation, and laboratory experiments on phase behavior. All these aspects combined have led to a favorable field test performance in the Donghe I reservoir.

Fault stability refers to the risk level of reactivation of the pre-existing fault in the stress field. Fault reactivation within the oilfield is mainly caused by the increase of fluid pressure in the fault zone. The quantitative evaluation index of the fault stability is the critical fluid pressure (that is, additional fluid pressure) required for fault reactivation under the current pore fluid pressure. When the formation pore pressure reaches the critical value, the corresponding fault part will be in the critical stress state. The sliding of the fault in the critical stress state will easily cause oil and gas leakage and casing damage at the edge of the fault. Therefore, it is of great significance to study fault stability for oilfield production. Ground stress is a key parameter for fault stability evaluation. There are many methods to calculate the geomechanics including hydraulic method, acoustic emission method, and the use of the logging data, among which the hydraulic fracturing method can be used to obtain the most accurate horizontal minimum principal stress. This paper calculates the continuous geomechanics by using the logging data. There are many methods available for evaluating fault stability, among which fault sealing analysis technology (FAST) method is most widely used. FAST can be used to not only quantitatively evaluate fault stability, but also evaluate the impact of fault cohesion on fault stability. There are many factors affecting fault stability. The relationship between the differential stress and tensile strength of the fault rock will affect the trend of the fault reactivation.The direction of the stress field also affects the fault stability greatly. The argillaceous material weakens the strength of fault rock. When a large amount of argillaceous material enters the fault zone, the fault tends to reactivate. The change of reservoir fluid pressure will also lead to the change of horizontal stress to affect the stability of the fault. In addition, the accuracy of seismic interpretation will also affect the evaluation results of fault stability. Based on the geological model framework and one-dimensional geomechanical model calibration, this paper establishes a three-dimensional geomechanical model by using the finite element simulation method to carry out four-dimensional geomechanical research to evaluate the fault stability in the development of the Donghe 1 Reservoir in Tarim basin. The research results show that the fracture sealing gradually strengthens during the development of Donghe 1 Reservoir, and the quantized critical fracture opening pressure is 67.38MPa.

This paper provide improved phase behavior models, trying to mitigate the problem that phase behavior of gas-crude system is difficult to describe in L block with low permeability and high water cut in China. This situation leads to a series of problems in CO2 flooding process and lower recovery up to expectations. The models is evaluated to possess both high calculation speed and accuracy compared with existing others. Characteristics of CO2-crude systems had been considered into repulsion-attraction type EOS (equation of state) based on the analysis of repulsion parameter and attraction parameter in EOS, and the improved EOS had been applied in developing calculation method of MMP (minimum miscible pressure). No ideality of CO2-crude systems had been considered into mixing rules of CO2-crude systems based on analysis of mixing rules of repulsion-attraction type EOS. Promotion had also been put into the obtain methods of parameters in phase behavior, including density, viscosity, MMP, critical parameters of plus components etc. All these methods are applied in L Block. The phase behavior models of CO2-crudes system promoted in this paper mainly include EOS, mixing rule and viscosity model and have been applied in CO2 flooding process in T Reservoir. The relative error of density calculation is reduced from 7% ∼ 20% to less than 1%and the modified EOS is applied to predict the MMP of the CO2-crude systems from 8 different blocks in T reservoir. The modified EOS also works well for the relative error of MMP prediction is reduced from 20% ∼ 70% to less than 5%. Compared with the existing mixing rules, the modified mixing rule is with higher calculation speed and accuracy. The relative error of components mole fraction calculation is reduced from 30% ∼ 80% to less than 10%. Compared with the existing viscosity models, there are large improvements of the modified viscosity model in accuracy. The relative error of viscosity simulation is reduced from more than 50% to about 5%. According to the simulation results, C2∼C15 are the key hydrocarbons with positive effect on the miscibility of CO2-crude systems, while C16+ are the key hydrocarbons with negative effect. The recovery of the pilot has increased by 23% by these methods. The improved phase behavior models provided in this paper possess as good performance as existing models in calculation speed, and accustom a big step forward in simulation accuracy. The modified components of the models also partially complete physical meaning in describing phase behavior of CO2-crude system. All the models mentioned above are finally applied in L block with HP/HT and high water cut and obtained an increase in recovery by 19.2%.

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This paper provide several improved miscible assistants, trying to mitigate the problem that CO2 miscible flooding is difficult to achieve in reservoirs because of the high miscible pressures, which leads to a lower recovery up to expectations. These miscible assistants could be easily mixed with crude oil by adding into CO2 and reduce the interfacial tension to drive down the minimum miscible pressure (MMP) in order to enhance sweep efficiency. Some efforts have been made to improve this situation. The effective method is to draw the experiences from structure characteristics of surfactants applied in micro emulsion of CO2-water systems. Amphiphilic organic assistants were designed to synthetize with fluoro-alkane chains and non-fluoro-OAc chains as the CO2-philic ends, as well as alkane structure as the lipophilic ends. The minimization of MMP of CO2 miscible processing assistants has been analyzed and optimized by surface tension testing in CO2-kerosene system and CO2-crude oil system. The crude oil was obtained from field test pilot in L Reservoir. The results of interfacial tension tests show that per-acetylated glucose dodecyl ester molecules have the ability to lower the interfacial tension most in these five kinds of new miscible processing assistants in two categories. Citric acid triisopropyl ester molecules take the second place, and others almost make no difference. The probable reason is that kerosene is mainly composed of C12 and lack of heavy components, which cause a weak interaction between independent hydroxyl of citric acid and tartaric acid assistant and hydrogen bond of kerosene. The results of interfacial tension tests show that all these miscible assistants possess good effects on minimizing the interfacial tension of the CO2-crudes system, and could also definitely reduce the MMP. Among these, per-acetylated glucose dodecyl ester molecules and citric acid isopropyl ester molecules perform most excellent, and could decrease the MMP of CO2 flooding by 27.5%. The assistants have been implemented in the CO2 flooding plan of L Reservoir with 4 gas injectors and 15 producers. After 15 years’ development simulation, cumulated oil production will reach 3.4 MMbbl with recovery increasing from 41.6% (only CO2 flooding) to 46.6%. Injection test shows that 1400 tons CO2 has been injected with 3800 bbl oil produced. The improved miscible assistants provided perform as well as other existing assistants in reducing interfacial tension and enhancing sweep efficiency in CO2 flooding. Compared with assistants of light hydrocarbon, these assistants require a little quantity to improve the miscible flooding, which could break the economic limits. Compared with the traditional fluoride assistants, these assistants are quite different in molecular structure and could cause little pollution and have been applied in field test.